Monitoring injected nonhydrocarbon and nonaqueous fluids through downhole fluid analysis

ABSTRACT

A method of monitoring a nonhydrocarbon and nonaqueous fluid injected into the earth&#39;s subsurface through a first wellbore that involves positioning a fluid analysis tool within a second wellbore and determining the presence of the injected nonhydrocarbon and nonaqueous fluid by making a measurement downhole on the injected nonhydrocarbon and nonaqueous fluid using the fluid analysis tool. Also a related method of enhancing hydrocarbon production from a subsurface area having first and second wellbores that involves injecting a nonhydrocarbon and nonaqueous fluid into the subsurface through the first wellbore, positioning a fluid analysis tool within the second wellbore, and determining the presence of the injected nonhydrocarbon and nonaqueous fluid by making a measurement downhole on the injected nonhydrocarbon and nonaqueous fluid using the fluid analysis tool. Further, a related method of determining the relative or absolute quantity of a nonhydrocarbon and nonaqueous fluid injected into the earth&#39;s subsurface through a first wellbore that involves positioning a fluid analysis tool within a second wellbore, measuring the near-infrared spectroscopy signature of fluid downhole using the fluid analysis tool, measuring the downhole temperature and pressure using the fluid analysis tool, and estimating a relative or absolute quantity of the injected nonhydrocarbon and nonaqueous fluid within said downhole fluid using the measured near-infrared spectroscopy signature, the temperature, and the pressure to estimate a partial pressure of hydrocarbon constituents of the downhole fluid.

CROSS-REFERENCE TO RELATED APPLICATIONS

A claim of priority is made to U.S. Provisional Patent Application No.60/809,887 filed Jun. 1, 2006 entitled DOWNHOLE FLUID ANALYSIS OFINJECTED NONHYDROCARBON AND NONAQUEOUS FLUIDS FOR PRODUCTIONENHANCEMENT, which is incorporated by reference.

FIELD OF THE INVENTION

This invention relates to the monitoring of nonhydrocarbon andnonaqueous fluids that have been injected into the subsurface of theEarth and, more particularly, to methods for monitoring nonhydrocarbonand nonaqueous fluids that have been injected into the subsurface of theEarth through the use of downhole fluid analysis and/or relatedtechniques, particularly in connection with enhancing hydrocarbonproduction from a subsurface area.

BACKGROUND

In certain hydrocarbon reservoirs, such the giant Cantarell field inMexico, nonhydrocarbon and nonaqueous fluids are injected to enhancehydrocarbon production. In the Cantarell field, one billion cubic feetof nitrogen are injected daily. A mixture of carbon dioxide and hydrogensulfide from The Great Plains Synfuels Plant in North Dakota, UnitedStates is being injected into the Weyburn field in Saskatchewan, Canadafor enhanced oil recovery and geological carbon dioxide sequestrationpurposes. These types of hydrocarbon production techniques are typicallyreferred to as enhanced or tertiary recovery techniques.

It is of central concern to understand the disposition of the injectedfluids. Clearly, if the injected fluid bypasses oil pockets or if thefluid reaches nonequilibrium concentrations in the hydrocarbons inplace, whether gas or oil, then the efficiency of production enhancementcan be greatly compromised. It is also possible for the injected fluidsto escape the intended geologic reservoir interval and potentiallymigrate back to the surface.

Using known techniques it would be possible to acquire several samplesdownhole as a function of position in the reservoir and to perform wellsite or laboratory analysis of the acquired samples. With thisinformation, one could hope to track the trajectory of the injectednonhydrocarbon and nonaqueous fluids. One significant problem with thisapproach is that it is difficult to adequately investigate likely fluidand reservoir complexities using a reasonable sample acquisition programbecause downhole fluid sampling tools can typically acquire a verylimited number of samples, typically less than ten, in a single loggingrun.

It is also possible to acquire samples of the produced fluid at thesurface and analyze the concentration of the injected fluid in theproduced fluid, but by the time the fluid reaches the surface, it istypically difficult or impossible to accurately determine the fractionof injected fluid in the reservoir fluid as it enters the borehole or todetermine at which location the injected fluid is entering the borehole.

Downhole Fluid Analysis (DFA), a suite of logging services developed bySchlumberger primarily for the open-hole hydrocarbon exploration wellenvironment, enable the real-time evaluation of fluid composition whilesampling thereby allowing a planned reservoir sample analysis program tobe modified as appropriate to further evaluate fluid complexities asthey are discovered. In a well, if an entire fluid column is found byprudent DFA station selection to be effectively homogenous then littlefurther analysis may be called for. However, if significant fluidcomplexities are discovered, then additional DFA station tests can beperformed. That is, if the evaluation program does not require filling(a necessarily finite number of) sample bottles, then one does not haveto cease a downhole fluid evaluation program simply because all of theavailable sample bottles have been filled. Of course, if corroborationof DFA results is desired, downhole sample acquisition and analysis canbe followed by surface analysis and used to complement the downholeanalysis.

If the injected fluid for production enhancement is water, then existingmethods of oil-water or gas-water differentiation could be employed tomonitor the progress of injected water through the reservoir. See, forinstance, “Method of analyzing oil and water flow streams”, Hines, Wada,Mullins, Tarvin, and Cramer, U.S. Pat. No. 5,331,156 (1995). If theinjected fluid is hydrocarbon gas, then standard methods of DFAdetermination of the gas-oil ratio could be employed. This type ofmethod is described in “Method and Apparatus for Downhole CompositionalAnalysis of Formation Gases”, Mullins and Wu, U.S. Pat. No. 5,859,430(1999) and “Method and Apparatus for determining Gas-Oil Ratio in aGeologic Formation through the use of spectroscopy”, Mullins, U.S. Pat.No. 5,939,717 (1999).

If methane or separator gas is injected into the reservoir, methods ofperforming DFA for hydrocarbon compositional determination could beemployed. In particular, near-infrared spectroscopy is currentlyemployed to quantify methane, other hydrocarbon gases, and highermolecular weight hydrocarbons. See, for instance, “Method and apparatusfor determining chemical composition of reservoir fluids”, Fujisawa,Mullins, Van Agthoven, Rabbito, and Jenet, U.S. Pat. No. 7,095,012(2006).

However, if the predominant constituents of the injected fluid aredifferent from hydrocarbon and water, new methods are called for tomonitor the progression of the injected fluids and/or to enhancehydrocarbon production from the subsurface in which the fluids areinjected.

SUMMARY OF INVENTION

One aspect of the invention is a method of monitoring a nonhydrocarbonand nonaqueous fluid injected into the earth's subsurface through afirst wellbore that involves positioning a fluid analysis tool within asecond wellbore and determining the presence of the injectednonhydrocarbon and nonaqueous fluid by making a measurement downhole onthe injected nonhydrocarbon and nonaqueous fluid using the fluidanalysis tool. Another aspect of the invention is a method of enhancinghydrocarbon production from a subsurface area having first and secondwellbores that involves injecting a nonhydrocarbon and nonaqueous fluidinto the subsurface through the first wellbore, positioning a fluidanalysis tool within the second wellbore, and determining the presenceof the injected nonhydrocarbon and nonaqueous fluid by making ameasurement downhole on the injected nonhydrocarbon and nonaqueous fluidusing the fluid analysis tool. A further aspect of the invention is amethod of determining the relative or absolute quantity of anonhydrocarbon and nonaqueous fluid injected into the earth's subsurfacethrough a first wellbore that involves positioning a fluid analysis toolwithin a second wellbore, measuring the near-infrared spectroscopysignature of fluid downhole using the fluid analysis tool, measuring thedownhole temperature and pressure using the fluid analysis tool, andestimating a relative or absolute quantity of the injectednonhydrocarbon and nonaqueous fluid within said downhole fluid using themeasured near-infrared spectroscopy signature, the temperature, and thepressure to estimate a partial pressure of hydrocarbon constituents ofthe downhole fluid. Further details and features of the invention willbecome more apparent from the detailed description that follows.

BRIEF DESCRIPTION OF FIGURES

The invention will be described in more detail below in conjunction withthe following Figures, in which:

FIG. 1 schematically illustrates an example of enhanced hydrocarbonproduction from a subsurface area using an injected nonhydrocarbon andnonaqueous fluid and of monitoring the injected fluid that can beperformed in accordance with the inventive method;

FIG. 2 is a flowchart depicting processes associated with certainembodiments of the present invention; and

FIG. 3 is another flowchart depicting additional processes associatedwith certain embodiments of the present invention.

DETAILED DESCRIPTION

FIG. 1 schematically illustrates an on-shore example of enhancedhydrocarbon production from a subsurface area using an injectednonhydrocarbon and nonaqueous fluid and of monitoring the injected fluidthat can be performed in accordance with the inventive method. In FIG.1, a Nonhydrocarbon and Nonaqueous Fluid 100 has been injected into aSubsurface Area 102 using a Injector Wellbore 104, typically referred toherein as a first wellbore. The injected Nonhydrocarbon and NonaqueousFluid 100 has passed through the subsurface and has been detected byFluid Analysis Tool 106, which has been positioned within ProducerWellbore 108. The Fluid Analysis Tool 106 may be placed within theProducer Wellbore 108 on wireline, slickline, coiled tubing, ordrillpipe, or may be temporarily, permanently, or semi-permanentlyinstalled with the well completion hardware within Producer Wellbore108.

References in this application to a “second wellbore” will oftencorrespond with a wellbore that is used to produce fluid from thesubsurface area of interest to the surface, although the inventivemethodology is equally as applicable if the second wellbore was drilledas an observation or monitoring well or was formerly used as an injectoror test well and is now being used to monitor the nonhydrocarbon andnonaqueous fluid injected into the subsurface area or as a producer.While the wells shown in FIG. 1 are essentially vertical, the inventivemethodology is also applicable when the wells are deviated, highlydeviated, or have substantially horizontal sections. Often a substantialnumber of an Injector Wellbores 104 and Producer Wellbores 108 will beused to enhance hydrocarbon production from a subsurface area and theymay be laid out in a regular grid pattern, such as a “nine spot” patternwhere eight producing wells are arranged in a square around a singleinjector well, for instance.

When the inventive technique is used in connection with enhanced oilrecovery purposes, the Nonhydrocarbon and Nonaqueous Fluid 100 will beinjected to help mobilize the residual in-situ hydrocarbons, move themaway from Injector Wellbore 104 and toward Producer Wellbore 108, wherethey can be pumped to the surface. It is not uncommon, however, for aparticular subsurface area Reservoir Interval 110 to have one or moreHigh Conductivity Zones 112 that allow the injected Nonhydrocarbon andNonaqueous Fluid 100 to preferentially flow from the Injector Wellbore104 to the Producer Wellbore 108 without sweeping a large fraction ofthe Reservoir Interval between the wellbores. These High ConductivityZones 112 could consist of high permeability geologic layers (sometimesreferred to as high perm streaks or super K thief zones) or structuralfeatures such as faults or fractures that have substantially higherpermeability than the reservoir rock matrix. The inventive methodologyhas been developed to allow these High Conductivity Zones 112 to beidentified and the problems they cause during enhanced oil recoveryoperations to be addressed.

Some of the processes associated with various embodiments of the presentinvention are depicted in flowchart form in FIG. 2. Inventive Process 10begins with the injection of the nonhydrocarbon and nonaqueous fluidinto a subsurface area through a first wellbore, which, as discussedabove, is typically referred to as an injector. This is shown in FIG. 1as Inject Fluid 12. The fluids injected will typically be a mixture ofdifferent chemical constituents and will almost always have at leastchemically detectable quantities of both hydrocarbons and water. Theinventive methodology may be used even when the fraction ofnonhydrocarbon and nonaqueous fluid in the injected mixture isrelatively small, certainly less than 50% on a mass fraction basis andpossibly even as low as even 1% to 5% of the injected mixture.Typically, the injected mixture will have significant quantities ofeither nitrogen, carbon dioxide, and/or hydrogen sulfide, but othernonhydrocarbon and nonaqueous fluids may also be used with the inventivemethod, such as air, air with some or substantially all of the oxygenremoved, combustion gases, or chemical plant byproducts or wastestreams. It may be desirable to custom formulate the injectednonhydrocarbon and nonaqueous fluid mixture on a case by case basisdepending on the particular type of hydrocarbon present in thesubsurface area, the cost of the material, available surface facilities,available wells and downhole completion hardware, etc. It has beenfound, for instance, that a predominantly carbon dioxide fluid dissolvesmore readily in certain types of oil when small quantities ofimpurities, such as hydrogen sulfide, are present. It may also bedesirable to alternately cycle between injecting nonhydrocarbon andnonaqueous fluid and injecting water and/or hydrocarbon gas. Theproduced fluid may be separated at the surface and the nonhydrocarbonand nonaqueous fluid may be reinjected into the reservoir.

A Fluid Analysis Tool is lowered within the second borehole in PositionTool 14. The Fluid Analysis Tool determines whether the injected fluidhas reached the position in the second wellbore where the tool islocated in Determine Presence of Injected Fluid 16. Various methods fordetermining the presence of injected nonhydrocarbon and nonaqueousfluids using a Fluid Analysis Tool are discussed in detail below.Typically, the Fluid Analysis Tool is then repositioned in RepositionTool 18 and the Determine Presence of Injected Fluid 16 process isrepeated.

The results of these measurements may then be compared in CompareMeasurements 20. The variation of the composition with position is oftenthe most important attribute to be determined (i.e. the relativefraction of the injected fluid in the sampled interval). This may beaddressable by performing any of a number of Fluid Comparison analyseson the physical and/or chemical measurement(s) of the two fluids inquestion. See, for instance, L. Venkataramanan, et al., “System andMethods of Deriving Differential Fluid Properties of Downhole Fluids”,U.S. patent application Ser. Nos. 11/132,545 and 11/207,043. TheReposition Tool 18, Determine Presence of Injected Fluid 16, and CompareMeasurements 20 process is typically repeated until all of the areaswithin the second wellbore under evaluation have been tested.

If one or more areas within the second wellbore that have highconcentrations of the injected nonhydrocarbon and nonaqueous fluid areidentified (shown in FIG. 2 as Identify Location Having HighConcentration 22), a well treatment may be performed to enhanceproduction (shown in FIG. 2 as Treat Well 24). This well treatment mayinhibit fluid from entering the wellbore at the identified location andflowing to the surface, such as the installation of a bridge plug, apacker, a casing patch, gel, or cement at a location within the wellborethat inhibits such fluid flow. Alternately, the well treatment couldenhance the production of fluid entering the wellbore from areas otherthan the identified location, such as by pressure fracturing, propellantfracturing, acidizing, or reperforating these other areas.

It is also possible to utilize the information obtained regarding thepresence of nonhydrocarbon and nonaqueous fluid to simulate the dynamicbehavior of the reservoir (shown in FIG. 2 as Simulate Reservoir 26) andto adjust the rate of production from the producer well (and typicallythe rates of production of any other producer wells associated with theinjector well) to optimize the sweep of the subsurface area. This isshown in FIG. 2 as Modify Production Rate 28. After a period of time,the entire process described above may be repeated.

There are numerous alternative types of measurements that can be used todetermine the presence of the injected fluid. If the injectedfluid/hydrocarbon mixture in the reservoir or in the producer wellborebecomes so saturated with injected fluid that the gas phase separatesfrom the liquid phase, then known methods of gas phase detection can beused such as those described in “Apparatus and method for detecting thepresence of gas in a borehole flow stream”, Mullins, Hines, Niwa andSafinya, U.S. Pat. No. 5,167,149 (1993) and “Apparatus and method fordetecting the presence of gas in a borehole flow stream”, Mullins,Hines, Niwa and Safinya, U.S. Pat. No. 5,201,220 (1994). It is alsopossible to detect evolved bubbles of injected gas as fluid enters thesecond wellbore or as it travels up the wellbore and the ambientpressure is reduced using oilfield production logging tools such as theFlow Scanner™ or GHOST™ tools available from Schlumberger.

If all or some of the injected gas dissolves in (i.e. is miscible with)the formation fluid, then the fluid phase transition parameters changeand this can be detected before the fluid begins to separate intodifferent gas and liquid phases. These parameters include bubble point,dew point and asphaltene onset pressures. For example, if the pressureis sufficiently high, significant quantities of nitrogen can dissolve inoil. Nitrogen is not particularly soluble in oil in comparison tomethane; thus, dissolved nitrogen would tend to come out of solution atmuch higher pressures than would equivalent quantities of methane. Onecan therefore map phase transition pressure as a function of position ina reservoir as a way to map injected fluid progression within thereservoir. In particular sensitive methods of gas detection are idealfor this purpose. Ultrasonic detection of gas phase evolution in acontinuous liquid phase is one such method. See, for instance, “Methodand Apparatus for the Detection of Bubble Point Pressure”, Bostrom,Griffin, and Kleinberg, U.S. Pat. No. 6,758,090 (2004).

If the injected gas has a separate signature from hydrocarbons, thenthis different signature can monitored along with any hydrocarbonsignature to map volume or mass fractions of formation fluid vs.injected fluid. Such is the case for CO₂ if near-infrared spectroscopy(NIR) is used. See, for instance, “Method of detecting CO₂ in a downholeenvironment”, Mullins, Rabbito, McGowan, Terabayashi, and Kazuyoshi,U.S. Pat. No. 6,465,775 (2002)

Many gases, however, do not possess a strong NIR signature. Diatomicnitrogen (the nitrogen in air) has no NIR absorption, this because ithas a center of symmetry. Thus, there can be no change in electricdipole moment with stretching of the nitrogen bond. Thus, one cannotdetect nitrogen by standard NIR absorption methods.

Other gases such as H₂S have exceedingly weak NIR signatures. For casessuch as N₂ or H₂S, an issue remains regarding how they may be detectedusing NIR measurements. Consider the extreme case of pure nitrogen underdownhole conditions of high pressure. Here the NIR spectrometer wouldindicate the absence of any hydrocarbons by virtue of the lack of anyNIR hydrocarbon absorption. However, the pressure is high indicatingthere is no vacuum. In the case of nitrogen injection into a hydrocarbonfield, the only gas that could be present without hydrocarbon absorptionfeatures yet with high pressure is nitrogen. Consequently, one candetect nitrogen because it represents the ‘missing mass’ in thismeasurement.

In fact, one can calculate the mass density or quantity of nitrogen byknowing the pressure, temperature, and compressibility factor Z fornitrogen at the measured downhole pressure and temperature conditions.Consider the less than extreme case where there is a small quantity ofhydrocarbon present in a large quantity of nitrogen. Here, the observedhydrocarbon absorption bands would be too small to account for themeasured high pressure analysis conditions. It has been established in“Linearity of alkane near-infrared spectra”, Mullins, Joshi, Groenzin,Daigle, Crowell, Joseph, and Jamaluddin, Appl. Spectros. 54, 624, (2000)that the NIR hydrocarbon bands are linear in the mass density of thehydrocarbon. One can therefore calculate the partial pressure of thehydrocarbon constituents of the sample. The remaining pressure wouldthen be presumed to result from nitrogen. Any of the various knownmixing laws would be presumed for the hydrocarbon/nitrogen mixture atreduced pressure and temperature. For instance, certain mixing laws werepresumed for nitrogen helium mixtures for downhole conditions ofpressure and temperature in “Gas detector response to high pressuregases”, Mullins, Schroeder, Rabbito, Applied Optics, 33, 7963 (1994)

These reduced variables can then be used to obtain a compressibilityfactor that is then compared with the measured pressure temperature andhydrocarbon band size. Composition adjustments may be made to obtain aself consistent mixture composition giving proper NIR hydrocarbon peaksizes at the proper pressure and temperature conditions.

This process is illustrated in FIG. 3, where the process of DeterminePresence of Injected Fluid 16 is shown as consisting of Measure NIRSignature 161, followed by Measure Temperature and Pressure 162, andEstimate Concentration 163.

Alternative methods for detecting fluids such as hydrogen sulfidedownhole are described in “Hydrogen sulfide detection method andapparatus”, Jiang, Jones, Mullins and Wu, U.S. Pat. No. 6,939,717 (2005)and “Methods and apparatus for the measurement of hydrogen sulphide andthiols in fluids”, Jiang, Jones, Brown and Gilbert, U.S. patentapplication Ser. No. 10/541,568, filed May 28, 2003.

Downhole gas chromatography is another way to achieve the directdetection of nitrogen or other types of injected nonhydrocarbon andnonaqueous fluids. Downhole equipment and methods of the type describedin “Self-Contained Chromatography System”, Bostrom and Kleinberg, U.S.patent application Ser. No. 11/296,150, filed Nov. 21, 2006 and “HeatSwitch for Chromatographic System and Method of Operation”, Bostrom,Daito, Shah, and Kleinberg, U.S. patent application Ser. No. 11/615,426,filed Dec. 22, 2006 may, for instance, be used in connection with thisprocess. Relatively high concentrations of nitrogen may, however, needto be present in the oil to detect the missing mass using downhole gaschromatography methods. The use of gas chromatography to detectnitrogen, carbon dioxide, and hydrogen sulfide is shown in Varian GCApplication Note Number 29, a copy of which may be found athttps://www.varianinc.com/media/sci/apps/gc29.pdf. However, NIR analysisof the separated gas phase may be much more sensitive to see the missingmass created by significant quantities of nitrogen. Consequently,intentionally causing a phase change and performing NIR analysis of thegas would be preferred to detect the presence and quantity ofsignificant amounts of gas.

It is also possible to detect the presence of the injected fluids or achemical product that indicates the presence of the injected fluid byusing one or more chemical sensors. Examples of the types of chemicalsensors that may be utilized with the inventive method can be found in“Systems and method for sensing using diamond based microelectrodes”,Jiang, Jones and Hall, U.S. patent application Ser. No. 10/638,610,filed Aug. 11, 2003 and “Fluid property sensors”, Goodwin, Donzier,Manrique, Pelham and Meeten, U.S. patent application Ser. No.10/104,495, filed Mar. 22, 2002.

All documents referenced herein are incorporated by reference. While theinvention has been described herein with reference to certain examplesand embodiments, it will be evident that various modifications andchanges may be made to the embodiments described above without departingfrom the scope of the invention as set forth in the claims.

1. A method of monitoring a nonhydrocarbon and nonaqueous fluid injectedinto the earth's subsurface through a first wellbore comprising:positioning a fluid analysis tool within a second wellbore; anddetermining the presence of said injected nonhydrocarbon and nonaqueousfluid by making a measurement downhole on said injected nonhydrocarbonand nonaqueous fluid using said fluid analysis tool.
 2. A method ofmonitoring a nonhydrocarbon and nonaqueous fluid in accordance withclaim 1, wherein said injected nonhydrocarbon and nonaqueous fluidcomprises one or more of nitrogen, carbon dioxide, or hydrogen sulfide.3. A method of monitoring a nonhydrocarbon and nonaqueous fluid inaccordance with claim 1, wherein said second wellbore has been used toproduce a mixture of fluids that includes both hydrocarbon fluid andsaid injected nonhydrocarbon and nonaqueous fluid.
 4. A method ofmonitoring a nonhydrocarbon and nonaqueous fluid in accordance withclaim 3, wherein said injected nonhydrocarbon and nonaqueous fluid is atleast partially miscible with said hydrocarbon fluid at ambient pressureand temperature of the location at which said fluid analysis tool ispositioned within said second wellbore.
 5. A method of monitoring anonhydrocarbon and nonaqueous fluid in accordance with claim 3, whereinin said nonhydrocarbon and nonaqueous fluid is present in suchquantities in the subsurface near the location at which said fluidanalysis tool is positioned within said second wellbore that said fluidis at least partially immiscible with said hydrocarbon fluid at thelocal pressure and temperature.
 6. A method of monitoring anonhydrocarbon and nonaqueous fluid in accordance with claim 1, whereinsaid determining the presence of said nonhydrocarbon and nonaqueousfluid using said fluid analysis tool comprising measuring theconcentration of said nonhydrocarbon and nonaqueous fluid in a mixtureof fluids that includes both hydrocarbon fluid and said nonhydrocarbonand nonaqueous fluid.
 7. A method of monitoring a nonhydrocarbon andnonaqueous fluid in accordance with claim 1, further comprisingmeasuring the downhole temperature and pressure using said fluidanalysis tool.
 8. A method of monitoring a nonhydrocarbon and nonaqueousfluid in accordance with claim 7, further comprising measuring thenear-infrared spectroscopy signature of fluid downhole and estimatingthe relative or absolute concentration of said injected nonhydrocarbonand nonaqueous fluid using said measured near-infrared spectroscopysignature, temperature, and pressure.
 9. A method of monitoring anonhydrocarbon and nonaqueous fluid in accordance with claim 7, whereindetermining the presence of said injected nonhydrocarbon and nonaqueousfluid using said fluid analysis tool comprises determining one or morephase transition parameters such as bubble point, dew point, orasphaltene onset pressure.
 10. A method of monitoring a nonhydrocarbonand nonaqueous fluid in accordance with claim 9, wherein said bubblepoint phase transition parameter is determined using ultrasonicdetection of gas phase evolution.
 11. A method of monitoring anonhydrocarbon and nonaqueous fluid in accordance with claim 1, furthercomprising repositioning said fluid analysis tool at a differentlocation within said second wellbore, determining the presence of saidinjected nonhydrocarbon and nonaqueous fluid at said different locationby making a measurement downhole on said injected nonhydrocarbon andnonaqueous fluid using said fluid analysis tool, and comparing themeasurements made at said different locations.
 12. A method ofmonitoring a nonhydrocarbon and nonaqueous fluid in accordance withclaim 1, wherein the presence of said injected nonhydrocarbon andnonaqueous fluid is determined using downhole gas chromatography.
 13. Amethod of enhancing hydrocarbon production from a subsurface area havingfirst and second wellbores comprising: injecting a nonhydrocarbon andnonaqueous fluid into the subsurface through said first wellbore;positioning a fluid analysis tool within said second wellbore; anddetermining the presence of said injected nonhydrocarbon and nonaqueousfluid by making a measurement downhole on said injected nonhydrocarbonand nonaqueous fluid using said fluid analysis tool.
 14. A method ofenhancing hydrocarbon production from a subsurface area in accordancewith claim 13, further comprising identifying a location within saidsecond wellbore where fluids with relatively high concentrations of saidinjected nonhydrocarbon and nonaqueous fluid are entering said secondwellbore.
 15. A method of enhancing hydrocarbon production from asubsurface area in accordance with claim 14, further comprisingperforming a treatment on said second wellbore.
 16. A method ofenhancing hydrocarbon production from a subsurface area in accordancewith claim 15, wherein said treatment inhibits fluid from entering saidsecond wellbore at said identified location and flowing to the surfacecomprises, such by installing one or more of a bridge plug, a packer, acasing patch, gel, or cement within said second wellbore.
 17. A methodof enhancing hydrocarbon production from a subsurface area in accordancewith claim 15, wherein said treatment well treatment enhances theproduction of fluid entering the wellbore from areas other than theidentified location, such as by pressure fracturing, propellantfracturing, acidizing, or reperforating these other areas.
 18. A methodof enhancing hydrocarbon production from a subsurface area in accordancewith claim 13, further comprising modifying the rate at which fluid isbeing withdrawn from said second wellbore.
 19. A method of determiningthe relative or absolute quantity of a nonhydrocarbon and nonaqueousfluid injected into the earth's subsurface through a first wellborecomprising: positioning a fluid analysis tool within a second wellbore,measuring the near-infrared spectroscopy signature of fluid downholeusing said fluid analysis tool, measuring the downhole temperature andpressure using said fluid analysis tool, and estimating a relative orabsolute quantity of said injected nonhydrocarbon and nonaqueous fluidwithin said downhole fluid using said measured near-infraredspectroscopy signature, said temperature, and said pressure to estimatea partial pressure of hydrocarbon constituents of said downhole fluid.